When a hydrocarbon-bearing, subterranean reservoir does not have enough permeability or flow capacity for the hydrocarbons to flow to the surface in economic quantities, hydraulic fracturing stimulation is often used to increase the flow capacity. The wellbore penetrating a subterranean reservoir typically consists of a metal pipe (casing) cemented into the original drill hole. Lateral holes (perforations) are shot through the casing and cement to allow hydrocarbon flow into the wellbore. When reserves are believed to be present, but a well completion is unable to flow hydrocarbons at acceptable rates due to low rock flow capacity, hydraulic fracture stimulation is often applied. Hydraulic fracturing consists of injecting viscous fluids (usually shear thinning, non-Newtonian gels or emulsions) into a reservoir at such high pressures and rates that the reservoir rock fails and forms a plane, typically vertical fracture much like the fracture that extends through a wooden log as a wedge is driven into it. Granular material, such as sand, is injected with the later portion of the fracturing fluid to hold the plane fracture open after the pressures are released. Increased flow capacity from the reservoir results from the easier flow path left between grains of the granular material within the plane fracture.
Application of hydraulic fracturing as described above is a routine part of petroleum industry operations as applied to target zones of up to about 60 meters (200 feet) of gross, vertical thickness of subterranean formation. When there are multiple or layered reservoirs to be hydraulically fractured, or a very thick hydrocarbon- bearing formation (over about 60 meters), then alternate treatment techniques are required to obtain treatment of the entire target zone. The methods for improving treatment coverage are known as diversion methods in petroleum industry terminology.
Prior to this invention, methods that have been used (or proposed for use) to provide fracture treatment diversion include mechanical diversion using bridge plugs or sand to isolate fracture intervals, limited entry using a very small number of perforations to maximize wellbore pressure, and diversion by ball sealers. Each of these methods has significant limitations as described below.
In mechanical diversion, the deepest interval is first perforated and fracture stimulated, then the interval is isolated mechanically and the process is repeated in the next interval up. For example, the deepest 30 meters (100 feet) of formation thickness might be perforated, fractured, and propped with sand. A mechanical bridge plug would then be placed within the casing just above the treated interval and the process repeated on the next 30 meters (100 feet). To treat 300 meters (1,000 feet) of formation in this manner would require ten jobs over a time interval of ten days to two weeks with not only multiple fracture treatments, but also multiple perforating and bridge plug running operations. At the end of the treatment process, a wellbore clean-out operation would be required to remove the bridge plugs and put the well on production. The major advantage of using mechanical separation is high confidence that the entire target zone is treated. The major disadvantages are the high cost of treatment and the risk of complications resulting from so many operations on the well. For example, a bridge plug can become stuck in the casing and need to be drilled out at great expense. A further disadvantage is that the required wellbore clean-out operation often damages some of the successfully fractured intervals.
An alternative to using bridge plugs is filling the just fractured interval of the wellbore with fracturing sand, commonly referred to as the Pine Island technique. The sand column essentially plugs off the already fractured interval and allows the next interval to be perforated and fractured independently. The primary advantage is elimination of the problems and risks associated with bridge plugs. The disadvantages are that the sand plug does not give a perfect hydraulic seal and it can be difficult to remove from the wellbore at the end of all the fracture stimulations. Unless the well's fluid production is strong enough to carry the sand from the wellbore, the well may still need to be cleaned out with a work-over rig. As before, additional wellbore operations increase costs, mechanical risks, and risks of damage to the fractured intervals.
Another possible process is limited entry diversion in which the entire target zone of the formation to be treated is perforated with a very small number of perforations, generally of small diameter, so that the pressure loss across those perforations during pumping promotes a high, internal wellbore pressure. The internal wellbore pressure is designed to be high enough to cause all of the perforated intervals to fracture at the same time. If the pressure were too low, only the weakest portions of the formation would fracture. The primary advantage is that there are no inside-the-casing obstructions like bridge plugs or sand to cause problems later. The disadvantage is that limited entry fracturing often does not work well for thick intervals because the resulting fracture is frequently too narrow (the proppant cannot all be pumped away into the narrow fracture and remains in the wellbore), and the initial, high wellbore pressure does not last. As the sand material is pumped, the perforation diameters are eroded to larger sizes that quickly reduce the internal wellbore pressure. The net result can be that not all of the target zone is stimulated.
The problem with failure to stimulate the entire target zone can be addressed by using limited, concentrated perforated intervals diverted by ball sealers. The zone to be treated could be divided into sub-zones with perforations at approximately the center of each of those sub-zones, or sub-zones could be selected based on analysis of the formation to target desired fracture locations. The fracture stages would then be pumped with diversion by ball sealers at the end of each stage. Specifically, 300 meters (1,000 feet) of gross formation might be divided into ten sub-zones of about 30 meters (about 100 feet) each. At the center of each 30 meter (100 foot) sub-zone, ten perforations might be shot at a density of three shots per meter (one shot per foot) of casing. A fracture stage would then be pumped with sand-laden fluid followed by ten ball sealers, one for each open perforation in a single perforation set or interval. The process would be repeated until all of the perforation sets were fractured.
FIG. 1 illustrates the general concept showing perforation intervals 2, 3, and 4 of an example well. In FIG. 1, interval 3 has been fractured and is in the process of being sealed by ball sealers 12 (in wellbore) and 14 (already seated on perforations), after which the wellbore pressure would rise causing another interval to break down. This technique presumes that each perforation interval or sub-zone would break down and fracture at sufficiently different pressure that each stage of treatment would enter only one set of perforations.
The primary advantages of ball sealer diversion are low cost and low risk of mechanical problems. Costs are low because the process can be completed in one continuous operation, usually during just a few hours of a single day. Only the ball sealers are left in the wellbore to either flow out with produced hydrocarbons or drop to the bottom of the well in an area known as the rat (or junk) hole. The primary disadvantage is the inability to be certain that only one set of perforations will fracture at a time so that the correct number of ball sealers are dropped at the end of each stage. In fact, optimal benefit of the process depends on one fracture stage entering the formation through only one perforation set and all other open perforations remaining substantially unaffected during that stage of treatment. Further disadvantages are lack of certainty that all of the perforated intervals will be treated and lack of knowledge of the order in which these intervals are treated while the job is in progress.
Accordingly, there is a need for a fracture treatment design method that can economically reduce the risks inherent in the currently available fracture treatment options for formations with multiple or layered reservoirs or with thickness exceeding about 60 meters (200 feet).